BreitBurn Energy CEO Discusses Q4 2011 Results - Earnings Call Transcript

| About: Breitburn Energy (BBEPQ)

BreitBurn Energy Partners, L.P. (BBEP) Q4 2011 Earnings Call February 28, 2012 1:00 PM ET


Greg Brown – EVP and General Counsel

Hal Washburn – CEO

Randy Breitenbach – President

Mark Pease – COO

Jim Jackson – CFO


Gil Yang – Bank of America Merrill Lynch

Ethan Bellamy – Robert W. Baird & Co

T J Schultz – RBC Capital Markets

Kevin Smith – Raymond James

Aaron Terry – K. Anderson


Ladies and gentlemen, thanks so much for standing by and welcome to the BreitBurn Energy Partners Inventor Conference Call. The Partnership’s new release, made earlier today, is available from its website at

During the presentation, all participants will be in a listen-only mode. Afterwards, securities analysts and institutional portfolio managers will be invited to participate in a question-and-answer session. (Operator instructions).

As a reminder, this call is being recorded, Tuesday, February 28, 2012. A replay of this call will be accessible until midnight, Wednesday, March 13, by dialing 877-870-5176 and entering conference ID 414015095. Again, the ID is 4015095. International callers should dial 858-384-5517. An achieve of this call will also be available on the BreitBurn website at

I would now like to turn the call over to Greg Brown, Executive Vice President and General Counsel of BreitBurn. Please go ahead, sir.

Greg Brown

Thanks, operator, and good morning everyone. Presenting this morning will be Hal Washburn, BreitBurn’s CEO, Rand Breitenbach, BreitBurn’s President, Mark Pease, BreitBurn’s Chief Operating Officer and Jim Jackson, BreitBurn’s Chief Financial Officer.

After their formal remarks, the call will be opened up for questions from securities analysts and institutional investors.

Let me just remind you that today’s conference call contains projects, guidance and other forward-looking statements within the meaning of the Federal Securities law. All statements, other than statements of historical fact, that address future activities and outcomes, are forward-looking statements. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ materially from those expressed or implied in such statements.

These forward-looking statements are our best estimates today and are based upon our current expectations and assumptions about future developments, many of which are beyond our control. Actual conditions and those assumptions may and probably will change from those we project over the course of the year. A detailed discussion of many of these uncertainties set forth from the cautionary statement relative to forward-looking information section of today’s release and under the heading Risk Factors Incorporated by Reference from our annual report on Form 10-K currently on file for the year ended December 31, 2010 and for the year ended December 31, 2011 which will be filed tomorrow. And our quarterly reports on Form 10-Q, our current reports on Form 8-K and our other filings with the Securities and Exchange Commission.

Except where legally required, the Partnership undertakes no obligation to update publically any forward-looking statements to reflect new information for changing events.

Additionally, during the course of today’s discussion, management will refer to adjusted EBITDA, which is a non-GAAP financial measure when discussing the Partnership’s financial results. Adjusted EBITDA is reconciled to it’s most directly comparable GAAP measure in the earnings press release made earlier this morning and posted on the Partnership’s website.

This non-GAAP financial measure should not be considered an alternate to GAAP measures such as net income, operating income, cash flow from operating activities or any other GAAP measure of liquidity or financial performance. Adjusted EBITDA is presented as management believes it provides additional information relative to the performance of the Partnership’s business. This non-GAAP financial measure may not be comparable to similarly titled measures of other publically traded partnerships or limited liability companies because all companies may not calculate adjusted EBITDA in the same manner.

So with that, let me turn the cal over to Hal.

Hal Washburn

Thank you, Greg. Welcome, everyone, and thank you for joining us today to discuss our fourth quarter and full-year results.

The Partnership’s had an exceptional year operating our existing properties with great success and growing our asset base with two strategic acquisitions. Our operations team did an excellent job managing our assets and optimizing operations throughout the year. Fourth quarter 2011 production of approximately 2.1 million BOE and full-year production of just over 7 million BOE were both record highs for the Partnership.

The acquisitions of the Greasewood Field and the Green River Basin assets added high quality complimentary assets to our portfolio. With them, we significantly expanded our presence in Wyoming, levered our strong operating and technical teams in the region and added several hundred future drilling locations.

The Partnership increased it’s crude reserves by 32.2 million BOE to 151.1 million BOE, representing a 27% increase from 118.9 million BOE at year-end 2010. Our reserve replacement from all sources was exceptional totalling 558% from 2011 production.

The Partnership also had very strong financial results. Fourth quarter 2011 adjusted EBITDA was a record quarterly high of $64.4 million and full-year 2011 adjusted EBITDA was approximately $225 million.

We’re pleased to announce the Q4 distribution of $0.45 per unit or $1.80 per unit on an annualized basis, which was paid in February. This represents seven consecutive quarters of distribution increases and a 9% increase in distributions over the course of the past year.

Overall, 2011 was a great year for the Partnership and we’re very well positioned for 2012 financially and operationally. Our capital budget for 2012 is $68 million. As you know, we’re fortunate to have a balance portfolio of all our gas-producing assets. We’ll be focusing our spending on oil-producing assets with approximately 95% of our capital spending allocated to oil-producing projects.

Excluding acquisitions, we expect production to be between 7.8 and 8.3 million BOE in 2012. This represents an increase of between 11% and 18% over 2011 total production.

We’re projecting adjusted EBITDA between 255 and 265 million for 2012, which represents an increase of between 13 and 17% above 2011 adjusted EBITDA.

These results, these expected results do not reflect any assumed acquisitions throughout the year. Of course, acquisitions are part of our business strategy. As you may know, we have significantly reduced our bank borrowings during the last few months and currently have less than $100 million drawn on a current borrowing base of approximately 788 million, given us ample financial flexibility to pursue our growth through acquisition strategy.

In 2012, we will continue to exercise consistent cash flow generation to support a strong coverage ratio and work to grow production by effectively our properties and efficiently executing our capital program.

We’re monitoring the progress of other players in the Michigan Utica Collingwood with shale play very closely and Cana Corporation was one of the more active players in the areas, recently announced results of two test wells that were very encouraging.

As you know, we have over 130,000 net acres in the Utica Collingwood, substantially all of which is held by production. This could represent an areas with significant potential for the Partnership and we will continue to monitor it closely.

The Partnership is also very pleased to have been included in the Alerian MLP Index in its latest round of rebalancing in December. We believe the inclusion will help drive demand for our units.

In addition, Quicksilver Resources competed the sale of their remaining common units in the Partnership in the fourth quarter. We believe these two events will be a net positive for the Partnership.

We believe the Partnership is poised for another strong year in 2012 and we thank our team for their excellence and our investors for their continued support.

With that, I’ll turn the call over to Randy who will briefly cover some selected results for the quarter and the year and discuss our hedging activity. Randy?

Randy Breitenbach

Thank you, Hal, and welcome, everyone. I will cover details of our commodity hedging activity and the impact of these derivative instruments on our fourth quarter and full year results.

For the fourth quarter of 2011, crude oil, natural gas and NGL sales revenues totaled 109.7 million compared to 97.4 million in the third quarter. The increase was primarily due to higher sales volumes for both crude oil and natural gas and higher crude oil prices.

For full year 2011, crude oil and natural gas revenues were 394.4 million, including realized losses on commodity derivative instruments, full year revenues were 378.3 million.

Our hedges have been especially valuable from a GAAP standpoint. Our realized natural gas prices for the fourth quarter averaged $6.02 per Mcf compared with Henry Hub natural gas prices of $3.33 per Mcf.

On the oil side, average realized crude oil and liquids prices were $84 per barrel, slightly lower than the NYMEX crude oil spot prices of approximately $94.01 per barrel for the same period.

Brent crude oil spot prices, which are an important benchmark for our California oil production, averaged $109.42 per barrel in the fourth quarter of 2011, compared to $113.24 in the third quarter of 2011.

For full-year 2011, our realized natural gas price averaged $6.58 per Mcf as compared to Henry Hub natural gas prices of $4.00 per Mcf. And our realized crude oil price, excluding realized loss from termination of oil derivatives, average $79.80 per barrel as compared to a NYMEX crude oil spot price of approximately $94.87 per barrel.

Non-cash unrealized losses from commodity derivative instruments for the fourth quarter was 8.6 million, primarily due to an increase in oil future prices during the quarter and partially offset by early terminations of derivative contracts.

The full-year 2011 non-cash unrealized gains from commodity derivative instruments were 97.7 million.

Consistent with our strategy to mitigate commodity price volitility, we continue to opportunistically layer in new hedges. So far in 2012, we have extended our commodity production portfolio, hedging 182,500 barrels of 2015 production at an average price of $98.50 per barrel.

An updated presentation of the Partnership’s commodity price protection portfolio, as of February 28, 2012 will be made available in the Event and Presentation section of the Investor Relations tab on our website.

As we move further into 2012, our hedge portfolio will continue to play a role in our overall business strategy. Hedging is a vital tool for mitigating market price volitility, stabilizing revenues and cash flows and supporting our borrowing base. A significant portion of our oil and gas volumes is well protected at attractive prices through the next four years.

Assuming the midpoint of 2012 product guidance is held flat, our production is hedged at 75% in 2012, 74% in 2013, 50% in 2014 and 46% in 2015.

Average annual prices during this period range between $92.05 and $101 per barrel for oil and $5.43 and $7.12 per MMBtu for gas. We will continue to evaluate and opportunistically add to our hedging portfolio in the future.

With that, I’ll turn your over to Mark Pease who will provide you with additional details on our operating performance. Mark?

Mark Pease

Thank, Randy. I’m pleased to say that we had very good operational performance in 2011. I’ll run through the results at the Partnership level and then discuss some of the details by division.

During the fourth quarter, we produced 2.07 million barrels of oil equivalent, compared to 1.68 million barrels of oil equivalent in the third quarter. The increase in production was primarily a result of the additional production from the properties acquired in Wyoming.

We were pleased to see production for our full-year 2011 grow to approximately 7.04 million barrels of oil equivalent or 19,300 barrels of oil equivalent per day. This production level is above the high end of our guidance range of 6.5 to 6.9 million barrels and represents a 5% increase from 2010 production of 18,400 barrels of oil per day.

Our overall production split for the year was approximately 56% natural gas and 44% crude oil and NGLs.

Lease operating expenses and processing fees, excluding transportation expenses were 36.7 million or $17. 77 per BOE for the fourth quarter.

Full-year 2011 operating expenses came in at 131.2 million or $18.54 per BOE, which is below the midpoint of our guidance range.

The full-year operating costs are about 5% higher than 2010 operating costs at $17.68 per barrel of oil equivalent primarily due to the inflationary pressure from rising oil prices. Average 2010 WTI oil pricing increased more than 20% compared to – or average 2011 increased more than 20% compared to 2010. And also, we had additional operating costs for new wells in Florida and higher Michigan well service repair and maintenance costs.

As we’ve said in the past, our costs are strongly influenced by the price of oil and natural gas and rising oil prices during the year have resulted in upward pressure on the cost of our services and materials.

We continue to focus much effort on our expenses and the operating team’s done a very good job controlling costs, particularly with the strong oil price growth in 2011 compared to 2010.

Total oil and gas capital expenditures in the fourth quarter were $16.3 million and $75.4 million for the full year. Capital expenditures were slightly above our 2011 guidance range due to expenditures on the newly-acquired Wyoming properties. Our original capital estimate did not include any capital for future acquisitions. And we also drilled one additional well in our Florida drilling program.

Let me update you on our year-end results and then I’ll go into a little bit more detail on our operating results.

As of December 31, 2011, our total estimated crude oil and gas reserves were 151.1 million barrels of oil equivalent. This compares to year-end 2010 reserves of 118.9 million barrels of oil equivalent and represents an increase of 27%.

Has Hal mentioned earlier, our reserve replacement from all sources, including acquisitions, economic performance revisions and capital was 558% of 2011 production. The year-end 2011 reserves consist of about 65% natural gas and 35% crude oil, and 87% of our crude reserves was classified as crude developed.

A standardized measure of future net cash flow from these reserves, discounted at 10% is approximately $1.7 billion using SEC pricing and costs effective for year-end 2011 calculations.

Of our total estimated crude reserves, 49% were located in Michigan, 29% in Wyoming, 14% in California, 7% in Florida and the remaining 1% was in Indiana and Kentucky.

Now, I’ll turn to the performance of our two operating divisions.

While we reorganized into Northern and Southern divisions during the course of 2011, for 2011 comparison purposes, we’ll refer to the old Eastern and Western divisions.

Production in the Eastern Division for the quarter, which included Michigan, Indiana and Kentucky came in a little less than 1% below last quarter, primarily due to scheduled downtime for plant maintenance and colder weather. For the year, net production was within our expectations.

Capital expenditures in the Eastern Division for the fourth quarter consisted of two drill wells, five rig completions and two facility optimization projects. These capital projects added incremental net production of about 700 Mcf per day. This was more than double our forecast rate and the project cost approximately 70% of forecast so the program was very successful.

For full-year 2011, the Eastern Division drilled 20 wells and completed 40 work overs and recompletions in facility optimization projects. These projects had a net initial production of about 5.7 million cubic feet per day. Overall, cost and production came in very close to pre-worked forecasts.

And shifting to the Western Division, fourth quarter production in the Western Division, which included California, Florida and Wyoming and also included the Greasewood and Evanston and Green River Basin acquisitions, came in about 69% higher than last quarter, primarily due to the Wyoming acquisitions and strong production results from California and our legacy Wyoming properties.

We had a very successful drilling program in our Santa Fe, Springsfield and California. During the third quarter, we drilled and completed three wells that had combined initial production of 210 barrels of oil per day, which was about 52% above forecast and we had a full quarter of production from these wells during the fourth quarter.

The Western Division controllable lease operating expense per barrel for the fourth quarter was higher than forecast due to strong commodity prices and higher-than-anticipated well pulling activity in our California and Wyoming fields. For the year, controllable LOE was about 1% above forecast.

Due to the high realized oil prices, taxes for the year were also above forecast.

In the fourth quarter, capital spending in the Western Division was focused on drilling in Florida and in the Greasewood field in Wyoming. The full year 2011 capital expenditures were spent to drill 15 wells and complete six work-overs and recompletions. These projects added net initial production of about 1,190 barrels of oil equivalent per day.

Let me make a few comments about the two Wyoming acquisitions. First, the integration of these assets – the integration of these assets is close to complete. We’ve had good success increasing production in the Greasewood Field. The field was producing about 450 barrels of oil per day net when we acquired it. And December production averaged about 790 barrels of oil per day now; a significant increase.

Operations on the assets in the Southwest part of Wyoming, which are essentially all natural gas, have transitioned smoothly. During the third and fourth quarter of last year, we were preparing to kick off the drilling program as we had several hundred future drilling locations. Our drilling plans were postponed due to the continued weakness in natural gas prices. We will revisit the program as natural gas prices improve.

Next, I’d like to turn to our operating guidance.

We expect our full-year 2012 crude oil and natural gas capital spending program to be approximately $68 million. This does not include capital for new acquisitions. This is lower than 2011 levels of approximately $75 million even though we have a significantly larger reserve base. This is a direct result of shifting our capital program to oil projects and away from natural gas. Approximately 95% of total capital will be spent on oil projects.

We’re forecasting production levels between 7.8 million barrels and 8.3 million barrels of oil equivalent. We anticipate spending approximately 605 of our 2012 capital in the Southern Division principally on oil projects in California and Florida and we will spend approximately 40% in the Northern Division, principally on oil projects in Michigan and Wyoming.

We plan to drill approximately 30 well, which represent about 65% of our total capital spending. For the 30 wells we plan to drill, 15 are expected to be in Wyoming, nine in Michigan, three in California and three in Florida.

Consistent with previous years, due to weather constraints in our Northern locations, we will only execute about 15% of our capital program during the first quarter with most of this work being done on Florida.

The majority of our capital activity will take place in the second and third quarters, which enables us to much better manage costs. 2012 will be no different for the operations team in terms of striving to operate efficiently and control costs; these will continue to be a strong focus for us.

The plan to continue to evaluate project economics for our oil and gas opportunities as commodity prices change over the course of the year and we will reallocate our capital to the projects that provide the best return for the company.

One other note before I turn the call over to Jim, in a February 17 release, [Inaudible] Corporation discussed initial results from two Utica Collingwood wells in Michigan saying they were excited about the results. These two wells tested 6.5 million cubic feet a day and 3.1 million cubic feet a day with about 90 barrels per million of liquids. These were seven-day tests.

BreitBurn holds more than 130,000 acres of [inaudible] in the Utica Collingwood and more than 85% of that acreage is held by shale production. This could be significant for our company and we will closely follow the industry activity.

With that, I’ll turn the call over to Jim.

Jim Jackson

Thank you, Mark. I’ll start by reviewing some more specific results for the quarter and the year and conclude with commentary on our 2012 guidance.

Oil and Natural Gas revenues including realized gains and losses on commodities derivative instruments were $80.9 million in the fourth quarter as compared to $105.4 million in the third quarter .

Realized losses on commodity derivative instruments were $28.9 million compared to realized gains of $8.1 million in the prior quarter.

Full-year 2011 revenues including realized gains and losses on commodity derivative instruments totaled $378.3 million. Including realized gains and losses and other operating revenues, total revenue for the year came in at $480.4 million representing a 35% increase as compared to $355.3 million in 2010.

Fourth quarter adjusted EBITDA reached a record quarterly high of $64.4 million as compared to $52.9 million in the third quarter. And full-year adjusted EBITDA was $225 million.

General and administrative expenses, excluding unit-based compensation expense were $9.5 million or $4.59 per BOE in the fourth quarter versus $8.6 million for $5.09 per BOE in the third quarter.

On a full-year basis, G&A costs, excluding unit-based compensation were $31.3 million compared to $24.5 million in 2010. This increase was due in part to approximately $2.5 million of acquisition related costs incurred during the year.

Full-year G&A excluding unit-based compensation expense was approximately $4.45 per BOE. Production and property taxes totaled $7.9 million in the quarter as compared to $6.7 million in the third quarter.

For 2011, production and property taxes totalled $26.6 million as compared to $20.5 million in 2010. The increase in taxes was principally due to higher production from the newly acquired Wyoming properties and higher crude oil prices during the year.

Net interest and other financing costs for the fourth quarter were $11.4 million compared to $9.3 million in the third quarter.

Cash interest expense including realized losses on interest rate swaps totaled $10.4 million in the fourth quarter of 2011.

Full-year cash interest expense totaled $37.8 million which is at the high end of our 2011 full-year guidance range of 36 to $38 million but reflects borrowings for our recent Wyoming acquisitions.

We recorded a net loss of $30.3 million or $0.51 per limited Partnership unit for the fourth quarter and net income of $110.7 million or $1.79 per unit for full year 2011.

Our outstanding long-term debt at the end of the fourth quarter was $825 million and consisted of borrowings of $520 million under our credit facility and $305 million in senior notes.

In January and February of 2012, the Partnership significantly reduced borrowings under its bank credit facility. On January 13, the Partnership closed the private offering of $250 million of 7.875% senior notes.

Net proceeds from the offering were used to repay a portion of our borrowings under the credit facility.

Subsequently, the Partnership also closed an offering of 9.2 million common units on Federal [inaudible]. Net proceeds from the offering were used to further reduce borrowings under our credit facility. As a result of these transactions, the Partnership had only $88 million outstanding under the credit facility as of February 27.

Now, I’ll review 2012 guidance which was announced in the press release we issued earlier this morning.

As Hal and Mark mentioned, excluding acquisitions, we are projecting total capital expenditures for full year to be between $66 and $70 million and our 2012 production is expected to be 7.8 million – between 7.8 million and 8.3 million BOE, excluding acquisitions.

As Mark mentioned, 2012 production guidance reflects reduced drilling activities on our gas properties due to the recent decline in natural gas prices.

We project our production mix for the year to be 57% gas, and 43% oil.

In addition, our California oil production representing approximately 30% of the total oil production is expected to be sold based on Brent pricing.

Average oil price differentials are expected to be between 88 and 90% for both WTI and Brent Crude Oil.

Average gas price differentials are expected to be between 102 and 104% of Henry Hub prices.

Our operations team will continue to focus on controlling costs in 2012. We expect 2012 operating costs to be between $18 and $20.50 per BOE. These estimated operating costs include lease operating expenses, processing fees and transportation expense. Expected transportation expense totals approximately $6.2 million in 2012, largely attributable to our Florida production.

Excluding transportation expense, our estimated operating costs per BOE are expected to range between $17.25 and $19.75 per BOE.

When estimating operating costs for 2012, we are assuming flat $95 per barrel WTI crude oil, $105 per barrel Brent crude oil and $3 per Mcf gas price levels. This contrast to the flat $80 per barrel WTI crude oil and $4.25 per Mcf gas prices we assumed in 2010.

Operating costs generally move with commodity prices but do not typically increase or decrease as rapidly as commodity prices.

Production taxes are expected to range between 9.5% and 10% of oil and gas revenues. This increase compared to 2011 reflects a higher mix of production coming from Wyoming, which has higher production taxes than our other operating areas.

We expect 2012 general and administrative expenses, excluding unit-based compensation to be between 31 million and $33 million, a slight increase over 2011 guidance and equal to approximately $3.98 per BOE based upon the midpoint of our production guidance range.

As Hal mentioned, the Partnership expects to generate adjusted EBITDA, a non-GAAP measure, of between $255 and $265 million in 2012. These expectations are based on a number of operating and other assumptions including commodity prices remaining at or near the oil and gas price levels mentioned earlier and reflect the benefit of the Partnership’s existing hedge portfolio.

We are forecasting a cash interest expense range of $52 to $54 million on our outstanding borrowings which reflects interest from both our senior notes and our bank credit facility. The interest expense on bank credit facility assumes one month LIBOR rate of 1% and includes the impact of interest rate swaps covering approximately $192 million of borrowing at a weighted average swap rate of 1.81%.

For 2012, our guidance for maintenance capital was $60 million, which represents approximately 23% of adjusted EBITDA based upon the midpoint of our guidance range.

In conclusion, I’d like to reiterate that 2011 was an outstanding year both operationally and financially, particularly on production EBITDA and we demonstrated our ability to make strategic acquisitions and successfully integrate them into our portfolio.

We look forward to another great year and we thank our unit holders for their continued support.

This concludes our formal remarks, operator, you may now open the call for questions.

Question-and-Answer Session


Thank you very much, (Operator instructions). And we will take our first question from Gil Yang with Bank of America Merrill Lynch.

Gil Yang – Bank of America Merrill Lynch

Good morning. Jim, can you count on what you expect to do with Bar and Base redetermination?

Jim Jackson

Sure, our – we work closely with our LEAD agent on the Bar and Base redetermination process. You know, we have seen their gas price specs move down modestly, and most recently, we’re not headed for Bar and Base redetermination for a few months. That being said, we’re also seeing them a little more aggressive on the oil side, so you know, I don’t know if those two things necessarily will cancel each other out, but I think increases in oil price assumption with our balanced portfolio, we hope it offsets significantly any reduction the banks might have because of their lower gas prices.

Gil Yang – Bank of America Merrill Lynch

What’s the price that you are going to have to use for gas, or internally, if they were to be set now, what would it be?

Jim Jackson

Gil, every bank has a different price deck, so you know, not in the position, not in the position to average all of those out on a call like this.

Gil Yang – Bank of America Merrill Lynch

Okay. Hey, Mark, just a, and you may have said this, but, why was LOE down fourth quarter versus third quarter?

Mark Pease

Well, we talked a little bit that third quarter yield, LOE was up because, you know, when you have the concentration on operations we have in Wyoming and Michigan, you know, you try to get all of your work done in the summer. So we’ve had a pretty significant amount of compression work and scheduled work that slowed in second and third quarters. So when you compare it third to fourth that’s the main reason fourth quarter is down.

Gil Yang – Bank of America Merrill Lynch

Okay, thanks.

Mark Pease

You bet.


All right, thank you very much, (Operator instructions). Next, we will go to Ethan Bellamy with Baird.

Ethan Bellamy – Robert W. Baird & Co

Hey guys, a couple of questions for you. What kind of results would it take out of Ancona or others for you guys to put someone into Michigan Utica?

Hal Washburn

You know, we are in a good position, Ethan, this is Hal, to be able to watch and see how this works out. You know, we hold virtually all of our production, our acreage by production from our Shallow or Antrim. So we’ll watch these guys for a while and see, you know, kind of what the next few wells do. We are not likely to go out and drill a lot of 100% Utica Collingwood wells ourselves, however, if we have the opportunity to participate, and gain knowledge and help improve our acreage we wouldn’t be totally against that.

Ethan Bellamy – Robert W. Baird & Co

Have you had anyone solicit you for your acreage there?

Hal Washburn

You know, there were a whole host of conversations that we had when the play first came about, they slowed down dramatically and they are just now restarting, so, nothing that we can report on right now.

Ethan Bellamy – Robert W. Baird & Co

Okay, with respect to your main CapEx outlet for this year, what kind of lumpiness, if any, should we expect?

Hal Washburn

As far as quarterly, or…

Ethan Bellamy – Robert W. Baird & Co

Yes, quarterly.

Hal Washburn

Hey, Mark, why don’t you handle that?

Mark Pease

You know, what you really see, is again, you know, it’s kind of tied with the comment that I made a minute ago on our operating costs, again, you know, our capitals relief really focused in our second, and third quarters. So typically, in the first quarter, one of them – you know, one of our lower quarters of production because we don’t spend a whole lot of capital there. So, it’s just a seasonal thing due to the colder weather up north will be – you know, we will concentrate capital in the summer, and so therefore, most of our production and – production and reserve increases have occurred in the summer time.

Ethan Bellamy – Robert W. Baird & Co

Okay, with respect to your oil-only inventory be it PUDs or un-booked locations that are probable, how does that look, I’m trying to get a sense of what your oil-only inventory looks like, and how long of a runway you’ve got if you’re just trying to go after the oily targets?

Hal Washburn

I’ll take a stab at this one, Mark, you can them, this is Hal again. You know, we do not have as many locations in the oil property portfolio as we do in the gas property portfolio, and we’ve got literally hundreds, I think we disclosed more than 600 locations with capita acquisition and we have a similar number, if not more, in Michigan. But really depending on gas prices. On the oil side, on the other hand, we have a tremendous amount of original oil in place under our properties – you know, particularly, in California. The remaining oil under our lease hold in California is well worth a billion barrels. We don’t have identified locations, too many of those fields, but we do have a huge resource and our technical and operating teams are focused on developing locations on those properties, or in those properties. But today, we don’t have hundreds of drilling locations in the oil assets like we do in the gas assets.

Ethan Bellamy – Robert W. Baird & Co

Thanks, Hal, are you going to run into any gas PUD vintage issues that could potentially see reserves come down?

Hal Washburn

That’s possible, you know, we don’t have a big PUD component in the reserve base at all to begin with, but you could come up with some issues, but it shouldn’t have a meaningful impact on our reserves. If you look at our reserves, there is high, high percentage of crude developed.

Ethan Bellamy – Robert W. Baird & Co

Okay, last question, and it maybe for Jim. Can you talk about what if any implications there are for BBEP, BBEP unit holders with respect to the filing of Pacific Coastal Trust in the administrative services agreement with [inaudible] Management?

Hal Washburn

Jim, go ahead.

Jim Jackson

Sure, I can do it, or you can, it doesn’t matter. We don’t see a big impact, the relationship should be maintained, the agreement will be renegotiated, but there is no reason for use to expect a big financial impact at all.

Ethan Bellamy – Robert W. Baird & Co

But it would be the correct interpretation to – that IPO is sort of eliminating a risk that that administrative service agreement goes away?

Jim Jackson

You know, you can’t be certain, but that – there’s probably, you know, it’s probably not going to go away with the IPO.

Ethan Bellamy – Robert W. Baird & Co

Got it, okay, thank you.


All right, thank you, next moving on we will go to T J Schultz with RBC Capital Markets.

T J Schultz – RBC Capital Markets

Hey guys, just a quick question on distributions. I guess given the current gas price environment I’m understanding the strong hedge position you will have, but how do you bond distribution growth versus building more coverage maybe as you look at your ability to add on an additional gas hedges and be out years?

Hal Washburn

T J, we are constantly looking at that and looking at future projections, we feel very comfortable with our current distributions, we also feel that the acquisition market is very robust, and so, we are not backing away from our goal which is distribution increases of 8 to 10% per year. As we’ve said, you know, consistently we can achieve that goal without making acquisitions. However, we do believe that the acquisition market is robust, then given our position with leverage and very low amount drawn up credit facility we’re well positioned to take advantage of those [inaudible].

T J Schultz – RBC Capital Markets

Okay, good, thanks. I guess, just given the focus on 2012 CapEx and the oil plays, just trying to get a feeling for kind of how you envision your crude production mix to ramp I guess into the end of 2012, and maybe into 2013?

Hal Washburn

Mark, you want to take a stab at that one, or Jim?

Mark Pease

I can do it qualitatively and not quantitatively. We do expect production in our Southern region to go up, Southern Division to go up over the year and that’s virtually all oil. And production in the Northern Division will come down slightly, but it’s mainly natural gas. I don’t have the exact numbers right here. Overall, through the year, production is about flattish. But the same comments that we made about, you know, in the third and fourth quarters, we were working hard to put together a pretty robust capital program drilling natural gas wells mainly in Wyoming but some in Michigan as well. And then as prices changed, we shifted that focus and the flip side of those deteriorating economics on gas wells is true for the oil wells. In fact, I was looking at some economics on some of our California properties just a couple days ago because we’re looking for areas we can ramp up activity there and compared to two years ago, the economic hurdle on reserves for a couple of our california fields is half of what it was because of higher oil price.

So we’re working had to add more projects and I’ll be surprised if you don’t see us add a few more oil projects throughout the year.

I know that’s a long answer to you, but oil production is going to go up in the year, gas production is going to come down.

T J Schultz – RBC Capital Markets

Okay, fair enough. Thanks, guys.


Now we’ll take a question from Kevin Smith with Raymond James.

Kevin Smith – Raymond James

Hi, gentlemen. Just the one question on Florida. I believe you mentioned you prepared [inaudible] and drilled three wells there. Have you already identified the locations and I guess really more to the point, I'm curious to know if you’ve got any plans to spud a horizontal well outside of Raccoon Point?

Hal Washburn

Mark, why don’t you handle that.

Mark Pease

Okay. Yes, there are three wells, two of them are outside Raccoon Point, in fact we just finished one in our Westfeld Field and we spud another one in Westfeld and it’s, you know, similar philosophy to Raccoon Point. You know, these fields are [inaudible] to get oil collected at the top of formation, so we drill vertical down to the top of the formation and then go horizontal trying to stay high in the structure. So same philosophy in Westfeld as we have in Raccoon Point.

So we’ve got two wells to do in Westfeld and then another well in Raccoon Point and you know, we continue to be pleased with the results. I think we’re on our seventh well now.

So we’ve had a continuous program for a couple of years, so we continue to look for other places. But we’ll have – short answer, we’ll have two wells in Westfeld this year and at least one well in Raccoon Point.

Kevin Smith – Raymond James

And I’m sorry, your first well at Westefeld is already on line?

Mark Pease

Yes, it is.

Kevin Smith – Raymond James

Okay. Care to discuss the production rates?

Mark Pease

We don’t normally give out rates by well, but I can tell you that it was very economic and a very, very good rate of return.

Kevin Smith – Raymond James

Okay. Do you have any well count in Westfeld, [inaudible] and Sunniland as far as how many locations you think you have?

Mark Pease

It’s still early in Wesetfeld. Again, we were pleased with the results on the first well, actually, we tested that idea there, which again, we’re just mainly trying to stay higher on structure. We’re testing similar but not exactly the same idea on the second well. We’ll know more after we get that well down and see what it does.

Kevin Smith – Raymond James

Okay. Thank you very much.


(Operator instructions). We’ll move onto a question from Aaron Terry with K Anderson.

Aaron Terry – K. Anderson

Hey, guys. I just wondered if you could comment a little bit more specifically on your Utica assets? I know the last time you guys had talked about it, back in 2010, Ancana was kind of testing in the [inaudible] County. Are they – where are they testing now? Can you guys talk about where they’re testing and where that is relative to your assets?

Hal Washburn

Sure. Mark, you want to answer that?

Mark Pease

I can cover that pretty quickly. We’ve got a big acreage position there, you know, a big part of our acreage is up in the Antrim, part of that is in Calcasa County, which is the county where Ancana did their tests and those two wells are located 8 to 10 miles from our acreage there. We also have some acreage in some deeper – or some fields that are deeper than the Antrim that are a little bit closer to the [inaudible]. They’re just south and just west of that.

So they’re sort of 8 to 10 miles from areas where we have a pretty significant acreage position.

Aaron Terry – K. Anderson

And would you guys be the working interest operators of those?

Mark Pease

Yes, we would. Unless we made some other deal with someone. Right now, most of the acreage that we have out there is 100%.

Aaron Terry – K. Anderson

And then just following up on operating costs and LOE, I know one of the things that you guys talked about being attractive about the Wyoming assets you guys picked up was low lifting costs. Have you guys fully integrated those to the extent that you – do you expect any OpEx reductions or how are those operator – those assets operated relative to your expectations?

Hal Washburn

Mark, why don’t you handle that?

Mark Pease

I think so far they’ve operated about as expected. I mean, it’s winter in Wyoming, so that’s always interesting, cold weather increases cost and whatnot. But we haven’t seen any big surprises out there. It’s a little too early to speculate on how many efficiencies we’ll have over and above what the prior operator did and I think the prior operator’s a good operator so – but we’ll work hard and see if we can’t do things a little efficient or a little better than they did.

Aaron Terry – K. Anderson

And kind of follow up also, seasonality of your LOE and OpEx, if we look at what you guys were able to achieve in 2011 with kind of the peak in Q3, is that kind of the same trend you’d expect from a seasonal perspective in 2012?

Hal Washburn

Yes. Q2 and Q3.

Aaron Terry – K. Anderson

Sounds good. Thanks, guys.


There are no further questions in the queue at this time. Mr. Washburn, I’ll turn the call back over to you for any closing remarks.

Hal Washburn

Great. Thank you, operator. On behalf of Randy, Mark, Jim, Greg and the entire BreitBurn team, I thank everyone on the call today for your participation. Operator, you may now bring this call to a close.


Great. Thank you. And again, that does conclude today’s conference call. Thank you, everyone for joining us. You many now disconnect.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to All other use is prohibited.


If you have any additional questions about our online transcripts, please contact us at: Thank you!